METHODS OF CALIBRATING A FLUID ANALYZER FOR USE IN A WELLBORE

• US 20110061439A1
• Filed: 07/03/2008
• Published: 03/17/2011
• Est. Priority Date: 07/10/2007
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Fujisawa, Go, Vannuffelen, Stephane, Jackson, Richard, Vasques, Ricardo R., Saputra, Ahmad, Dong, Chengli, O'Keefe, Michael, Mullins, Oliver C., Hegeman, Peter S.
• Granted Patent: US 8,555,696 B2
• Time in Patent Office: Days
• US Class Current: 73/1.03
• CPC Class Codes: E21B 49/08 Obtaining fluid samples or testing fluids, in boreholes or wells
• CPC Class Codes: G01N 33/2823 raw oil, drilling fluid or polyphasic mixtures hydrocarbon content of earth materials G01N33/241; prospecting G01V; drilling per se E21B
• CPC Class Codes: G01N 35/00693 Calibration

Abstract

Methods of calibrating a fluid analyzer for use in a wellbore are described. An example method of generating calibration data for a fluid analyzer for use in a downhole tool involves lowering a downhole tool including a fluid analyzer to a location in a wellbore, measuring, via the fluid analyzer, a characteristic value of a calibration fluid or a vacuum while the fluid analyzer is at the location, obtaining an expected characteristic value for the calibration fluid or the vacuum at the location, and comparing the measured characteristic value to the expected characteristic value to generate a calibration value for the fluid.

Claims

1. A method of generating calibration data for a fluid analyzer for use in a downhole tool, comprising:

lowering a downhole tool including a fluid analyzer to a location in a wellbore;

measuring, via the fluid analyzer, a characteristic value of a calibration fluid or a vacuum while the fluid analyzer is at the location;

obtaining an expected characteristic value for the calibration fluid or the vacuum at the location; and

comparing the measured characteristic value to the expected characteristic value to generate a calibration value for the fluid analyzer.

2. The method as defined in claim 1, wherein the calibration fluid is substantially different in composition than a formation fluid to be measured by fluid analyzer.

3. The method as defined in claim 1, wherein measuring the characteristic value of the calibration fluid or the vacuum comprises measuring spectral information.

4. The method as defined in claim 1, wherein the measured characteristic value and the expected characteristic value are optical density values.

5. The method as defined in claim 1, further comprising sampling a formation fluid while the fluid analyzer is at the location and using the calibration value prior to sampling the formation fluid or after sampling the formation fluid to generate a corrected characteristic value for the formation fluid.

6. The method as defined in claim 1, wherein the calibration fluid is at least one of an alkane, an oil, water, air, nitrogen, carbon disulfide, or carbon dioxide.

7. The method as defined in claim 1, wherein measuring the characteristic value of the calibration fluid or the vacuum comprises measuring optical density values at a plurality of wavelengths.

8. The method as defined in claim 1, further comprising obtaining the calibration fluid from a flowline of the downhole tool or a sample container of the downhole tool.

9. The method as defined in claim 8, further comprising disposing the calibration fluid in the flowline or the sample container prior to lowering the downhole tool into the wellbore.

10. The method as defined in claim 1, wherein obtaining the expected characteristic value comprises multiplying a first value corresponding to a characteristic of the calibration fluid at surface conditions by a second value representing a change in the density of the calibration fluid at the location relative to the surface conditions.

11. The method as defined in claim 10, wherein the first value is an optical density value.

12. The method as defined in claim 10, wherein the second value is a ratio of a value representing the density of the calibration fluid at the location and a value representing the density of the calibration fluid at the surface conditions.

13. The method as defined in claim 12, wherein the value representing the density of the calibration fluid at the location is obtained using a density estimating equation or a density measurement made by the downhole tool at the location.

14. The method as defined in claim 1, wherein obtaining the expected characteristic value comprises using conditions at the location to derive the expected characteristic value from a measurement of the calibration fluid made at the surface.

15. The method as defined in claim 14, wherein the measurement of the calibration fluid made at the surface comprises measuring an optical characteristic of the calibration fluid at the surface.

16. The method as defined in claim 14, wherein the measurement of the calibration fluid made at the surface is performed at expected downhole conditions.

17. The method as defined in claim 16, wherein the expected downhole conditions comprise a pressure and a temperature associated with the location.

18. The method as defined in claim 1, further comprising performing a baseline calibration of the fluid analyzer at the surface prior to lowering the downhole tool into the wellbore.

19. The method as defined in claim 18, wherein the baseline calibration comprises measuring a response of the fluid analyzer to air at surface conditions.

20. The method as defined in claim 1, wherein comparing the measured characteristic value to the expected characteristic value to generate the calibration value comprises determining a difference between the measured characteristic value and the expected characteristic value.

21. The method as defined in claim 1, wherein measuring the characteristic value of the calibration fluid or the vacuum comprises measuring a viscosity, measuring a resistivity, or performing a nuclear magnetic resonance measurement.

22. A method of calibrating a fluid analyzer for use in a downhole tool, comprising:

lowering a downhole tool, including a fluid analyzer, into a wellbore;

measuring, via the fluid analyzer, a characteristic of a calibration fluid or a vacuum while the downhole tool is in the wellbore; and

using the measured characteristic and an expected characteristic of the calibration fluid or the vacuum to calibrate the fluid analyzer.

23. A method as defined in claim 22, wherein the calibration fluid is substantially different in composition than a formation fluid to be measured by the fluid analyzer.

24. The method as defined in claim 22, wherein measuring the characteristic of the calibration fluid or the vacuum while the downhole tool is in the wellbore comprises measuring the characteristic of the calibration fluid while the downhole tool is being run-in-hole.

25. The method as defined in claim 22, wherein measuring the characteristic of the calibration fluid or the vacuum comprises measuring a spectral characteristic of the calibration fluid or the vacuum.

26. The method as defined in claim 25, wherein the spectral characteristic comprises optical density values at a plurality of wavelengths.

27. The method as defined in claim 22, wherein using the measured characteristic and the expected to calibrate the fluid analyzer comprises comparing the expected characteristic to the measured characteristic and using the result of the comparison to calibrate the fluid analyzer.

28. The method as defined in claim 27, wherein the expected characteristic is based on a known response of the calibration fluid or the vacuum to downhole conditions.

29. The method as defined in claim 27, wherein using the result of the comparison to calibrate the fluid analyzer comprises adjusting a baseline value of the fluid analyzer based on a difference between the expected characteristic and the measured characteristic.

30. A method of generating calibration information for a fluid analyzer, comprising:

measuring a response of the fluid analyzer to a calibration fluid or a vacuum at a location in a wellbore;

comparing the measured response of the fluid analyzer to an expected response to the calibration fluid or the vacuum; and

generating calibration information based on the comparison of the measured response and the expected response.

31. The method as defined in claim 30, repeating the measuring, comparing and generating operations for multiple locations in the wellbore.

32. The method as defined in claim 30, further comprising obtaining the calibration fluid from a storage location within a downhole tool associated with the fluid analyzer.

33. The method as defined in claim 30, wherein comparing the measured response and the expected response comprises comparing spectral data.